Francisco Leon: You do need permits for sidetrack, Scott. It’s a little bit different process. We’ve seen not only CRC pursuing this, but most of the other operators in the state have been using the sidetrack inventory. So relatively high confidence that we’re going to be able to unlock multiple options here as the year progresses. Still very much looking for resolution on Kern County EIR, anticipate hearing more than likely in the first quarter, first half of next year. So that’s still moving forward. We don’t have any new updates other than the briefs have been completed and the decision is likely early next year. But we see multiple paths to getting back to drilling wells in sidetrack. It’s an exciting opportunity, different permitting process, but ultimately in line with the expectation to satisfy all the requirements from some of the agencies that we need to.
It’s something that we’ve done over the years. The industry is very comfortable doing that. So we feel that’s a path forward. And as you said, Sacramento Basin different counties, different needs for the product will be out there as well. So we’re advancing all fronts and difficult to handicap which one comes first, but we’re growing more and more comfortable that there will be a solution in the second half of next year.
Scott Hanold: Okay. And then just to clarify again, you are actively getting permits in the Sacramento Basin for gas wells, you are getting — you’re pursuing permits in the sidetracks and [indiscernible] yards. So you’re all doing that at this point in parallel with hoping that Kern County EIR comes through right now. Is that a fair statement? Or is that something that you’re still working towards?
Francisco Leon: No, no, we’re pursuing all fronts. We still haven’t received a new permit this year, to be very clear. But we are pursuing all the fronts that we laid out as solutions towards getting back on track. So all of the above, Kern County EIR, field level EIR, sidetracks or drilling outside of Kern County, all are — the team is working on all of them. And yes, we look forward to getting back on the phone in the February next year with our plans for 2024.
Scott Hanold: Got it. And then maybe a little bit on the CMB business. You talked about the Elk Hills gas plant. And obviously, it’d be, I guess, the first brownfield went out there now that you guys have contracted with yourselves for. You already discussed a little bit on the economic parameters. I’m just kind of curious, how does that economics work if in these are, to your understanding, still right now 45Q LCFS eligible? And are you sharing that credit with the JV? So is there some benefit to like CRC by itself through this process as well?
Francisco Leon: There is. So we — the way to think about this project, the CRC is investing into the capture equipment. It’s a little bit different from what ultimately we’ll do on bigger scale because this is a pre-combustion capture system. So low capital requirements with a piece of equipment with the CGP1 cryogenic plant already functioning and operating. So this is an add-on to that facility, low capital pre-combustion and that’s a CRC expense. So yes, we will look for 45Q. We’ll look for LCFS. We’ll look for all the incentives that are available to CCS. But on top of that, the plant — there’s benefits to CRC on the plant itself. We expect a higher yield of NGL, specifically propane. A little bit more production as well.
You should — I mean, we are reducing the emissions not entirely, but we are reducing the emissions of the plant system. So should expect the carbon tax reduction. So there will be — there are economics specific to CRC, beyond CCS, right? So the way to think about it is the capture system is what earns the 45Q. We pay a fee storage fee to the JV, consistent to what we are asking others to pay, but there are multiple benefits for CRC as well that accrues to the CRC shareholders. So it’s a very nice project, nice win, I wish we had the ability to control all aspects of projects in terms of CCS. That’s not the case. But this one is a great proof point, a great way to showcase that things are working. And very importantly, this is the way to get CCCI on the ground by 2025, should be the fastest in the state and ultimately earn the 45 good credit and solve a lot of the questions out there in terms of feasibility of CCS.
So having more control points is very helpful to get to that answer.
Scott Hanold: Thank you.
Operator: Thank you. And our next question comes from Leo Mariani with ROTH MKM. Please go ahead.
Leo Mariani: Hey guys. A few questions around some of these numbers that you’ve thrown out here. So the first one is on this kind of $45 million sort of resource adequacy payment from the state. I guess you’re saying that’s kind of roughly doubling in 2024 versus 2023. I just wanted to make sure I sort of understood the mechanics around that. Is this basically the state been cutting you a check so far in 2023 for that amount? And that amount sort of doubles next year? Does this flow through your sort of electricity business margins or if you guys are selling the power, maybe you don’t really get the check there? I’m just trying to kind of understand if that’s kind of free money for being on standby or if you are producing, then maybe you don’t get all of that. Just kind of some help around the mechanics here would be great.
Francisco Leon: Great question. So as you know, the state of California has a big penetration of renewable energy and that doesn’t work 24/7. So you require baseload from different sources to make sure the lights are on in the state. So years ago, California entered into this resource adequacy program through the utilities that they pay independent power producers to be on standby. Let me turn it over to Jay Bys, if he has a few more thoughts around regulators adequacy and what it means.
Jay Bys: Yes, thanks. Just to be really clear, the state is not actually paying for capacity. Anybody serving load in the state in CAISO in particular is required to have capacity to back that load. So whether that’s a utility or an aggregator, they have to secure the capacity necessary to back up the load, which they’re serving. So they are, in fact, partly paying CRC to make this capacity available. Historically, there had been maybe more lax treatment and how much and to the extent by which certain parties would back up their supply using this marketplace. But CAISO has become very resolute that they want — they do want people to be backing up their load. So you’re seeing a price that’s reflective of the true market value of this capacity today. And the fact that we have an asset that’s readily available at all times is certainly attractive to the marketplace.
Francisco Leon: And Leo, just to add one more, just to clarify. So we have 550 megawatts at Elk Hills. We use about a third of that power for our own consumption in the oilfield and two third is available to sell to CAISO and into utilities. So this is a way to guarantee that supply to this resource adequacy program. And it’s another way to kind of showcase that you want to be long commodity and long power in the state that’s struggling to keep up otherwise.
Leo Mariani: Okay. Maybe I can just try to phrase this a little bit differently. If the plant pretty much runs at the same rate in 2024 as it does in 2023 and let’s say all other variables are the same such as power pricing, input costs, etcetera, are you getting an extra $45 million next year in the business?
Francisco Leon: Correct. That’s exactly what — and typically, that comes in the third quarter. That’s what we got just now the payment for 2023. These are contracted capacity that the team has already executed on. So it’s an incremental $45 million of cash. Correct.
